This invention is in the field of oil and gas production, and is more specifically directed to the real-time monitoring of fluid flow rates for multiple fluid phases from hydrocarbon wells.
Hydrocarbon production from subterranean reservoirs typically involves multiple wells positioned at various locations of a reservoir. In a given reservoir, the multiple wells are not only deployed at different surface locations, but are also often of different “geometry” from one another, and are also often drilled to different depths. Many typical wells also produce fluids at multiple depths along a single wellbore, thus producing from multiple subsurface strata. As is fundamental in the art, the fluid produced from a given well, as viewed at the wellhead, often includes multiple “phases”, typically natural gas, petroleum or oil, and water. As used herein, the term “phase composition” or simply “phase” in reference to produced fluid refers to the relative amounts of water, oil and gases in the produced fluid. The produced fluid may also contain suspended solids such as sand or asphaltene compounds. In addition, as is well-known in the art, one or more wells into a reservoir may be configured for the injection of fluids, typically gas or water, for secondary recovery and other reservoir management functions.
Knowledge of the rate of production and phase composition of the produced fluids are important properties for effective reservoir management and also for management of individual wells. Reservoir management typically includes the selection of the number of wells to be deployed in a production field, the locations and depths of these wells, the configuration of wells as production or injection wells, and decisions regarding whether to shut-in wells, or convert wells from production to injection wells or vice versa. Well management refers to decisions regarding individual wells, for example decisions regarding whether to perform remedial actions along the wellbore to improve production. Knowledge of production rate and phase information is, of course, also important from an economic standpoint.
Rate and phase information is commonly determined using flow meters or other equipment. For example, separating equipment may be located at or near a wellhead to separate produced phases so that the volume of each phase can be determined Valves downstream from the separators divert all or a portion of the production stream for a separated phase to a flow meter or the like for measurement of the flow rate of that particular phase. Typically, this diversion is performed only periodically for each phase, for example once per month for a span of twelve hours, because of the effort and flow interruption involved in re-directing the flow of the various phases. This lack of real-time flow measurements of course reduces confidence in the measurements obtained, and in the decisions made based on those measurements.
In addition to the cumbersome nature of these flow measurements, conventional flow meters generally require frequent calibration to ensure accuracy, considering the typical drift of conventional flow meters over time. Conventional flow meters are also typically calibrated to be accurate only within a certain operating range. If operating conditions change so that the steady-state condition of a well drifts outside the operating range, the flow measurements can be unreliable. In either case, calibration drift or change in operating conditions, the flow meter must be recalibrated, adjusted, or replaced, each action usually requiring physical intervention.
While recalibration and maintenance of flow meters is somewhat cumbersome for land-based wells, the recalibration and maintenance of flow meters is typically prohibitively difficult and costly in marine environments. In addition, the inability to service offshore flow meters can cause total loss of flow measurement if a critical sensor fails. Deep sea marine environments present particularly significant challenges for maintenance or otherwise routine operations. For example, flow meters located within a well or at a wellhead can be prohibitively difficult to recalibrate due to the difficult access for maintenance, as costly intervention vessels and other equipment are often required.
In addition, not all wells in a production field are equipped with a dedicated flow meter. Rather, many wells share access to flow meters with other wells in the field. This is especially true in off-shore production, because of the difficulty of maintaining sea-bed downhole sensors in the deep-sea environment. This sharing has been observed to add uncertainty in rate and phase measurements. Typically, in such a shared metering environment, especially offshore, production from several wells is commingled before reaching any platform or other topside facility. As used herein, “topside” in reference to equipment or facilities means equipment or facilities which are located either at or above ground for land-based wells, or at or above the water surface for sea environments (e.g., production platforms and shore-bound surface facilities). In either case, shared topside flow metering typically does not allow determination of production from individual wells without stopping production from other wells.
By way of further background, U.S. Patent Application Publication No. 2004/0084180 describes a method of estimating multi-phase flow rates at each of multiple production string entries located at varying depths along a wellbore, and thus from different production zones of a single well. According to the method of this publication, a volumetric flow rate for each phase is obtained at the wellhead, which of course includes production from each of the downhole production zones. The measured volumetric wellhead flow, along with downhole pressure and temperature measurements, are applied to a well model to iteratively solve for estimates of the flow rate of each phase at each downhole production string entry location.
By way of further background, software packages for modeling the hydraulics of hydrocarbon wells, as useful in the design and optimization of well performance, are known in the art. These conventional modeling packages include the PROSPER modeling program available from Petroleum Experts Ltd, the PIPESIM modeling program available from Schlumberger, and the WELLFLOW modeling program available from Halliburton. These software modeling packages utilize actual measured, or estimated, values of flow, pressure, and temperature parameters to characterize the modeled well and to estimate its overall performance. In addition, these modeling packages can assist in decision making, for example by evaluating the effect on well performance of proposed changes in its operation.
By way of still further background, U.S. Patent Application Publication No. US 2005/0149307 A1, published Jul. 7, 2005, describes the use of well models in reservoir management. Pressure measurements, multi-phase flow rates, etc. are applied to a well production model, and the model is verified based on various well and reservoir measurements and parameters.
The conventional uses of well modeling in well and reservoir management, especially involving the determination of rate and phase values, operate as “snapshots” in time. In other words, the various measurements acquired in the field are applied to the well model “off-line”, with the well model operated by a human engineer or other operator to determine an estimate of the state of the well. In many instances, the measurements are obtained or inferred from well tests, such as shut-in tests, during which the well is shut-in suddenly, and the subsequent response of the measured pressure is recorded. Such well testing is, of course, infrequent in a producing field. And as is well-known in the art, substantial human effort and judgment required to select an appropriate well model for a particular set of measurements, to apply judgment and filtering to measurements that appear to be inaccurate, and to evaluate the well model results.
By way of further background, the deployment of downhole pressure and temperature sensors has become increasingly common in recent years, because of improvement in the reliability and long-term performance of such downhole sensors. These modern downhole sensors can now provide measurement data on a continuous and near real time basis, with measurement frequencies exceeding one-per-second.